Testing system for petroleum wells having a fluidic system including a gas leg, a liquid leg, and bypass conduits in communication with multiple multiphase flow metering systems with valves to control fluid flow through the fluidic system

ABSTRACT

A well test system for testing fluids produced from one or more petroleum wells has a separator and a plurality of multiphase flow metering systems, each of which has the capability, over at least a portion of its operating envelope, of separately measuring flow rates of oil, water, and gas. The well test system has a fluidic system, including gas leg conduits coupling the separator to the multiphase flow metering systems, liquid leg conduits coupling separator to the multiphase flow metering systems, and bypass conduits for directing multiphase fluid to the multiphase flow metering systems while bypassing the separator. Valves are configured to selectively route fluid flow though the fluidic system to selectively bypass the separator when the multiphase flow metering systems can be used to provide separate flow rates of oil, water, and gas in the unseparated multiphase fluids from the well.

FIELD OF INVENTION

The present invention relates generally to systems and methods formetering multiphase flows, and more particularly to systems and methodsfor metering flow from a multiphase fluid source, such as a petroleumwell, that may produce a multiphase flow having variable content.

BACKGROUND

In the oil and gas industry, the output of a production well is usuallya multiphase mixture of oil, water, and gas, commonly referred to asthree-phase flow. The gas itself can be present in two forms: as freegas in the form of bubbles or slugs, or as dissolved gas tightly boundto the liquid. The relative proportions of free and dissolved gas varywith many factors, most notably pressure. Thus, for the same wellproduction stream with constant mass flow rates of oil, water and gas,the proportion of gas coming out of solution to become free gas willincrease as the line pressure decreases downstream. Accurate assessmentof the output of each well is important for reservoir management, aswell as for the payment of royalties and taxation.

The output of each petroleum well could be measured on a continuousbasis with a dedicated metering system capable of monitoring the threephase simultaneously. Such a device is known as a three-phase flowmeter. Unfortunately, it is at present uneconomic to meter wellsindividually using dedicated three-phase flow meters. As discussedbelow, the most widely used system for measuring three-phase flow is theseparator, which physically separates at least the gas and the liquid.In many separator systems the oil and water are also separated.Separator systems are large and expensive, and it is uneconomic toprovide a separator for each well. Instead, the industry has developedthe practice of using well test stations, where the outputs of manywells are brought together to share a single multiphase measurementsystem, i.e. a test separator.

Referring to FIG. 1, a conventional well test separator selects 1 of Nwells (where N is typically 6-60) and directs the multiphase flow from awell that has been selected for testing into a separator system so thatthe well output can be tested or measured. The outputs from all theunselected wells are typically pooled and sent unmeasured to theproduction facility, bypassing the test separator. Once the testing ofthe selected well is complete, a different well can be selected fortesting. Thus, all N wells can eventually be tested one at a time usingthe conventional test separator.

FIG. 2 shows a conventional separator system in more detail. Themultiphase flow is directed into a separator vessel, which hassufficient capacity to enable the gravimetric separation of at least theliquid (e.g., oil and water) from the gas. Other separator designs haveadditional features to enable the further separation of the oil from thewater. The separated gas rises, and is piped away on the “gas leg” to bemetered by a suitable gas flow measurement device, such as a vortexmeter or a Coriolis mass flow meter. Similarly, the liquids are pipedaway on the “liquid leg” to be metered by a suitable liquid flowmeasurement device, such as a positive displacement meter, a vortexmeter, or a Coriolis mass flow meter. Further measurements can be takento determine the ‘water cut’, or proportion by volume of water withinthe liquid mixture, so that the individual oil and water flow rates canbe calculated. For example, a water cut meter can be incorporated intothe liquid leg. Alternatively, if a Coriolis meter is used to meter theliquid, its density reading can be used to determine the water cut.

A range of techniques, familiar to those skilled in the art, may be usedto manage the separation and measurement of the liquid and gas streamsby conventional separator systems. Typically, level and/or pressurecontrol is used. For example, the level of the liquid in the separatormay be maintained between an upper and lower limit, or the pressure atthe top of the separator may be maintained between an upper and lowerpressure limit, or some combination of the two may be implemented. Flowout of the separator through the liquid and/or gas legs may occurcontinuously or in batches, depending upon the control schemeimplemented. In any event, phase separation entails gravimetricseparation of the various constituents of the multiphase flow, whichrequires the separator tank or vessel to be large enough to provide asuitable setting time for allowing gravimetric separation of the fluids.Because of the settling time in the separator vessel, there is no way tocorrelate instantaneous gas or liquid flow rate measurements with anyinstantaneous flow rates into the separator vessel. In other words,there is no way to correlate the instantaneous oil, water and gas flowrates of the well being tested with the instantaneous flow outputs fromthe separator.

For example, FIG. 3 shows the observed flow pattern from a conventionalseparator as it monitors an oil and gas well over a two hour testperiod. The upper plot shows the flow measurement reported on the liquidleg, in tons per day (t/d), while the lower graph shows the reportedflow measurement on the gas leg, in standard cubic meters per day. Inthis example, the separator control scheme operates so that liquidnormally flows through the liquid leg meter, but from time to time (forexample when the pressure in the separator reaches an upper limit) a gaspurge takes place, where the liquid leg is shut off and the gas leg isopened up to expel gas from the separator and meter the gas. Each gaspurge is characterized by an initial spike in gas flowrate, followed bya sharp decline and then a more gradual decline. When the separatorpressure drops to its lower limit, the gas leg is closed and the liquidleg is reopened.

Over a sufficiently long period the flow entering the separator mustequal the flow leaving the separator. However, the original flowbehavior from the well is largely destroyed by the separation process.The pattern of flow exiting the separator and recorded by the gas andliquid meters is mostly determined by the separator control scheme, notthe pattern of flow entering the separator. For example, it is likelythat the gas flow rate from the well is more continuous than the patternof gas purges observed in the gas leg. Thus, no real-time information onthe pattern of well flow is provided by this conventional separatorsystem. Typically, therefore, for each well test, only the totalizedflows of gas and liquid (sometimes further distinguished as oil andwater) are reported, along with the totalized time. Thus, a separatorcan be used to determine average flow rates for each of the phases, butnot the dynamic flow behavior.

A further limitation of separators, which follows from this interruptedpattern of flow, is that a long testing period is often necessary toensure accurate measurements. For example, in FIG. 3, the time delaybetween gas purges is up to 50 minutes. If the test had been completedimmediately before the final gas purge, say at 11:30, the average gasflow rate reported would have been quite different. Thus, given that thegas and/or liquid streams may leave the separator in a series of cycles,it is important to ensure the test period is long enough to havesufficient separator cycles so that incomplete cycles at the beginningor end of the test period do not introduce significant errors. Whenswitching between wells that are being tested, it also is important toset aside sufficient time to flush the separator through completely withthe new well stream before starting a new test or additional measurementerrors will be introduced. These issues limit the ability to test wellsquickly.

FIG. 4 illustrates another problem that can occur when using aconventional test separator. If gas/liquid separation is incomplete(e.g., if an emulsion is formed, or if the separator is undersized forthe well flow rate), then gas carry under and/or liquid carry over maytake place. Gas carry under occurs when gas leaves the separator throughthe liquid leg. Liquid carry over occurs when liquid leaves theseparator through the gas leg. FIG. 4 shows liquid carry-over occurringat the very start of a test period, in data collected from the sameseparator with the same control schemes as shown in FIG. 3. The topgraph shows the liquid flow rate leaving the separator, which isessentially steady other than the regular drops in flow when the liquidleg is closed for gas purges. The middle graph shows the gas flow ratereading from a Coriolis mass flow rate meter on the gas leg. There areregular bursts of gas flow coinciding with each of the pauses in liquidflow, as expected, but the graph is dominated by the first burst of gasoccurring at time 16:25. The bottom graph shows the density reading fromthe Coriolis meter on the gas leg. The density time series demonstratesthat for much of the test the density is around 30 kg/m3, which is theexpected value for the gas composition and the operational pressure.However, at the initial purge of gas at time 16:25, the density rises toabove 400 kg/m3. This can only have been caused by liquid carry-over,where liquid is carried through into the gas leg, resulting in a veryhigh density reading from the Coriolis meter on the gas leg. In thiscase the liquid carry over appears to cause a large over-reading of thegas mass flow before the end of the liquid carry over event. Similarly,in the case of gas carry under, when gas/liquid separation is incompleteit is possible for some gas to be passed through the liquid leg, whichmay introduce errors in the liquid flow meter. Gas carry under in theliquid leg can be detected by density readings from the liquid leg thatare too low.

A related potential problem with the conventional separator arrangementin FIG. 2 concerns the effects of dissolved gas. As is well known tothose familiar with the industry, natural gas readily dissolves in oil.The amount of gas dissolving in the oil is a function of severalparameters, including temperature and pressure. Specifically, at higherpressures more gas can be dissolved into a given volume of oil.Accordingly, at each stage of the upstream oil and gas productionprocess, whenever the pressure decreases, some gas will be released fromsolution in the oil. Thus, even when there is no gas carry under, thepressure drop across the liquid meter will induce a proportion of gas tocome out of solution, and in that sense the fluid measured in the liquidleg is not purely liquid because of the gas therein. Even small amountsof gas coming out of solution can cause significant measurement errorsin some conventional liquid phase meters, for example some conventionalCoriolis meters.

Moreover, each separator is typically used to test the outputs from manywells, and so must be designed to deal with the range of flow conditionsacross all these wells, as characterized by liquid volumetric flowrate,water cut, GVF, pressure and other parameters. Choosing the mostappropriate capacity for a separator, given the set of wells to betested, is a matter of balancing different considerations. It isdesirable to minimize the separator size in order to keep the cost ofconstruction as low as possible. However, if the capacity of theseparator is too small for high flowing wells, the separation processmay be incomplete, leading to liquid carry over and/or gas carry underwith the likelihood of measurement errors induced in the gas and liquidleg flow meters. On the other hand, if the capacity of the separator istoo large, then for low flowing wells the test period may need to besignificantly extended to ensure sufficient separator gas purge cyclesfor the desired measurement accuracy. In practice, a single separatorcan be used in the industry to measure a well cluster with a wide rangeof well flow rates—for example a ratio of 20:1—between the highest andlowest liquid flow rate. However, the need to accommodate a wide rangeof flow rates does limit the options available for well testing.

The present inventor has developed systems and methods that improve onthe conventional systems described above and which will be described indetail below.

SUMMARY

One aspect of the invention is a system for testing production of fluidsby one or more petroleum wells. The system includes a separator. Theseparator has an inlet for receiving a multiphase fluid flow from apetroleum well, a vessel for containing fluids received through theinlet, a liquid outlet, and a gas outlet. The gas outlet is positionedat a higher elevation on the vessel than the liquid outlet. The systemalso includes first and second multiphase flow metering systems. Each ofthe first and second multiphase flow metering systems has thecapability, over at least a portion of its operating envelope, ofseparately measuring flow rates of oil, water, and gas through therespective flow metering system. The system also includes a fluidicsystem that has: (i) gas leg conduits fluidicly coupling the gas outletof the separator to the first and second multiphase flowmeters; (ii)liquid leg conduits fluidicly coupling the liquid outlet of theseparator to the first and second multiphase flow metering systems;(iii) bypass conduits plumbed to direct multiphase fluid through thefluidic system to the first and second multiphase flow metering systemswithout flowing the fluid through the separator to thereby bypass theseparator; and (iv) a plurality of valves configured to selectivelycontrol routing of fluid flow though the fluidic system.

Another aspect of the invention is a system for testing production offluids by individual petroleum wells in a group of N petroleum wells.The system has a fluidic system for receiving multiphase fluid outputfrom the wells. The system also has a fluid measurement systemconfigured to measure flow rate of oil, water, and gas through thefluidic system. The fluid measurement system is operable in a first modein which the measurement system provides time-varying measurements ofindividual flow rates for oil, water, and gas received by the fluidicsystem, wherein the time-varying measurements generally correspond toinstantaneous flow rates of oil, water, and gas into the fluidicsystems. The fluid measurement system is also operable in a second modein which the measurement system separates gas from the oil and water andprovides flow measurements of oil, water, and gas generallycorresponding to at least one of: (i) total flow over a period of time;and (ii) average flow rate over a period of time. The system has acontrol system configured to selectively and sequentially route theoutput of one or more wells selected from the group of N wells to thefluidic system to perform a series of well tests on the wells. Thecontrol system is further configured to cause the measurement system toswitch between the first and second modes in response to a change inoperating conditions.

Yet another aspect of the invention is a method of testing fluidsproduced by individual petroleum wells in a group of N petroleum wells.The method includes routing fluid from one or more wells selected fortesting to a well test system. The well test system including aseparator vessel, a plurality of multiphase metering systems, and afluidic system for receiving multiphase fluid output from the one ormore wells. The method also includes determining whether or not theplurality of multiphase metering systems can, either individually orcollectively, provide individual measurements of oil, water, and gas.The fluid is selectively routed to the separator vessel when it isdetermined the plurality of multiphase metering systems cannot provideindividual measurements of oil, water, and gas. The fluid is selectivelyrouted directly to one or more of the plurality of multiphase meteringunits, bypassing the separator, when it is determined the multiphasemetering units can provide individual measurements of oil, water, andgas.

Other objects and features will in part be apparent and in part pointedout hereinafter.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a prior art test separator system beingused to test multiphase output from one well selected from a group of Nwells;

FIG. 2 is a schematic diagram of the test separator from FIG. 1;

FIG. 3 is a set of graphs illustrating flow rates of gas and liquid fromthe test separator in FIG. 2 during a well test;

FIG. 4 is a set of graphs illustrating flow rates of gas and liquid aswell as measured “gas” density during a liquid carry over event;

FIG. 5 is a schematic diagram of one embodiment of a multiphase testsystem of the present invention being used to test a selected well froma group of N wells;

FIG. 6 is a schematic diagram illustrating the multiphase test system inmore detail;

FIG. 7 is a front elevation of one embodiment of a net oil skid that canbe used to measure flow rate of individual components of a three-phaseflow from the separator of the multiphase test system illustrated inFIGS. 5 and 6;

FIG. 8 is a schematic diagram illustrating one embodiment of anelectronic architecture for the net oil skid illustrated in FIG. 7;

FIG. 9 is a set of graphs illustrating volumetric fraction for eachconstituent of a three-phase flow from a petroleum well and flow ratefor each constitute of the three-phase flow;

FIG. 10 is a schematic diagram illustrating one embodiment of anelectronic architecture suitable for use in a multiphase test system,such as the multiphase test system illustrated in FIG. 6; and

FIG. 11 is a schematic diagram illustrating another embodiment of amultiphase test system similar to the embodiment illustrated in FIG. 6but with a third multiphase metering system included.

Corresponding reference characters indicate corresponding partsthroughout the drawings.

DETAILED DESCRIPTION

Referring now to the drawings, first to FIGS. 5 and 6, one embodiment ofa system for testing fluids produced by one or more petroleum wells in acluster of N wells is generally designated 101.

The system includes a separator 103, as illustrated in FIG. 6. Ingeneral, any device that separates gas from liquids using gravity can beused as the separator. For example, any conventional separator can beused as the separator in the system. As illustrated in FIG. 6, theseparator 103 includes an inlet 105 for receiving a multiphase fluidflow from a petroleum well and a vessel 107 for containing fluidsreceived through the inlet. The separator 103 also includes a liquidoutlet 109 and a gas outlet 111. The gas outlet 111 is positioned at ahigher elevation on the vessel 107 than the liquid outlet 109. Inparticular, the liquid outlet 109 is suitably positioned near the bottomof the vessel 107 to facilitate draining liquid completely from thevessel and to limit the potential for gas carry under. The gas outlet111 is suitably positioned near the top of the vessel 107 fordischarging gas from the vessel while limiting the potential for liquidcarry over.

In addition to the separator 103, the system also includes a pluralityof multiphase flow metering systems 121, 123. Each of the multiphaseflow metering systems 121, 123 has the capability to receive amultiphase flow containing oil, water, and gas and provide separate flowrate measurements for flow of oil, water, and gas therethrough over atleast a portion of its operating envelope. For example, one or both ofthe multiphase flow metering systems 121, 123 can suitably include amultiphase Coriolis meter, such as the Coriolis flowmeters described inU.S. Pat. Nos. 6,311,136; 6,505,519; 6,950,760; 7,059,199; 7,614,312;7,660,681; 7,617,055; the contents of which are each hereby incorporatedby reference. One or both of the multiphase metering systems 121, 123can also include a water cut meter that measures the amount of water inthe multiphase flow in combination with a Coriolis flowmeter or othertype of flowmeter that is operable to measure liquids (e.g., oil andwater) separately from gas.

FIG. 7 illustrates one embodiment of a multiphase metering system 131that is suitable for use in the system 101. The multiphase meteringsystem 131 illustrated in FIG. 7 is generally known as a net oil skid.The net oil skid 131 in the illustrated embodiment includes a multiphaseCoriolis flowmeter 133 in series with a water cut meter 135. Togetherthe Coriolis meter 133 and water cut meter 135 can provide independentmeasurement of oil, water, and gas flow through the net oil skid 131.For example, the multiphase Coriolis meter 133 can suitably provideseparate flow rate measurements for the gas phase and the combinedliquid phases (e.g., flow rate of oil plus flow rate of water) while thewater cut meter 135 can provide a measurement indicating the percentageof water in the combined liquid phases. Thus, the information providedby the Coriolis and water cut meters 133, 135 enables determination ofindependent flow rates for each constituent of the three phase oil,water, and gas mixture produced by one or more of the petroleum wells.For example, each net oil skid 131 may include a net oil computer 137that receives information from the Coriolis meter 133 and also from thewater cut meter 135 and computes the flow rates for oil, water, and gasthrough the net oil skid 131 based on that information. Alternatively, asingle net oil computer may be shared by a plurality of multiphasemetering systems 131 within the scope of the invention. For example,each of the flow metering systems 121, 123 of the system illustrated inFIG. 6 can be a net oils skid as illustrated in FIG. 7 and they mayshare a single net oil computer 137. It is understood that differentarrangements of Coriolis meters and water cut meters can be used.

It is not required that the multiphase flow metering systems be able toprovide three phase flow measurements under all types of conditions. Forexample, some Coriolis flowmeters provide suitable measurements whenoperating under low to moderate gas void fraction conditions (e.g.,about 50% GVF or less) but do not operate as well under high gas voidfraction conditions (e.g., more than about 50% GVF). Although each ofthe flowmeters 121, 123 in the illustrated embodiment includes aCoriolis flowmeter 133 in combination with a water cut meter 135, it isunderstood that Coriolis meters are not required to practice theinvention and other types of multiphase flowmeters could be used insteadwithout departing from the broad scope of the invention. It isconceivable that other types of multiphase metering systems may need adifferent set of operating conditions in order to provide suitablyindependent measurements of the flow rates for oil, water, and gas.

The multiphase metering systems 121, 123 can provide total flowmeasurements for the total amount of oil, water, and/or gas flowingtherethrough even when the operating conditions are outside the envelopthat is suitable for operation in multiphase mode. In other words, eachof the multiphase metering systems 121, 123 suitably has a narroweroperating envelop within which they can be operated to provide dynamicmultiphase measurements of each component of a three phase mixture ofoil, water, and gas and also a broader operating envelop within whichthey can at least provide useful total flow measurements even if theyare outside the narrower envelop that allows measurement of individualflow rates of oil, water, and gas.

For reasons that will become apparent, it may be desirable for each ofthe multiphase flow metering systems to have a different maximum flowrate capacity. For example, in a system having two multiphase flowmetering systems one of the multiphase flow metering systems suitablyhas a relatively higher maximum flow rate capacity while the other has arelatively lower maximum flow rate capacity. The multiphase flowmetering systems can suitably have different minimum flow rates as well.For example, referring to the embodiment illustrated in FIG. 6, one ofthe multiphase metering systems 121 suitably has an operating range fromabout 1 to about 5 units while the other 123 has an operating range fromabout 5 to about 20 units. In this embodiment, there is no gap betweenthe operating ranges for the metering systems 121, 123. Similarly, themultiphase flow metering systems 121, 123 can be used, eithercollectively or individually, to measure any total flow rate between thelowest minimum flow rate for the smaller capacity system (e.g., 1 unit)to the sum of the maximum flow rates for both systems (e.g., 25 units).

A fluidic system 141 connects the separator 103 to the multiphase flowmetering systems 121, 123. As illustrated in FIG. 6, for instance, gasleg conduits 143 fluidicly couple the gas outlet 111 of the separator103 to the first and second multiphase flow metering systems 121, 123.Liquid leg conduits 145 fluidicly couple the liquid outlet 109 of theseparator 103 to the first and second multiphase flow metering systems121, 123. The fluidic system 141 in FIG. 6 also includes bypass conduits147 plumbed to direct multiphase fluid through the fluidic system to thefirst and/or second multiphase flow metering systems 121, 123 withoutflowing the fluid through the separator 103 to thereby bypass theseparator. The fluidic system 141 also includes a plurality of valves151 configured to selectively control routing of fluid flow though thefluidic system.

In the embodiment illustrated in FIG. 6, for example, the gas legconduits 143 include an upstream conduit 143 a and a set of downstreamconduits 143 b arranged so each of the multiphase flow metering systems121, 123 is connected to the upstream gas leg conduit 143 a by one ofdownstream gas leg conduits 143 b. Thus, in FIG. 6 for example the gasleg conduits 143 include two downstream gas leg conduits 143 b branchingfrom the upstream gas leg conduit 143 a because there are two multiphaseflow metering systems 121, 123. The number of downstream gas legconduits could be increased to accommodate additional multiphase flowmetering systems. Similarly, the liquid leg conduits 145 also include anupstream conduit 145 a and a set of downstream conduits 145 b arrangedso each of the multiphase flow metering systems 121, 123 is connected tothe upstream liquid leg conduit 145 a by one of the downstream liquidleg conduits 145 b. Again, additional downstream liquid leg conduitscould be added to accommodate additional multiphase flow meteringsystems, if desired. Likewise, the bypass conduits 147 also include anupstream conduit 147 a and a set of downstream conduits 147 b arrangedso each of the multiphase flow metering systems 121, 123 is connected tothe upstream bypass conduit 147 a by one of the downstream bypassconduits 147 b.

Still referring to FIG. 6, the plurality of valves include a set ofvalves 153 a, 153 b in the gas leg conduits 143 that control flow offluid through the gas leg conduits. One of the valves 153 a in the gasleg conduits is positioned in the upstream gas conduit 143 a (e.g., nearthe separator 103) and is configured to selectively open the gas legconduits 143 for receiving flow from the gas outlet 111 into theupstream gas leg conduit 143 a. Further, each of the downstream gas legconduits 143 b has a valve 153 b that is configured to selectively openand close the respective downstream gas leg conduits 143 b. Thus, thevalves 153 b in the downstream gas leg conduits 143 b are operable toselectively route fluid flow from the upstream gas leg conduit 143 toone or more of the multiphase flow metering systems 121, 123. Forexample, the valves 153 b in the downstream gas leg conduits can beoperated to switch flow through the gas leg conduits 143 back and forthfrom one of the multiphase flow metering systems 121, 123 to the otherto reroute the flow of fluid through the gas leg conduits 143.

The plurality of valves also includes a set of valves 155 a, 155 b inthe liquid leg conduits 145 that control flow of fluid through theliquid leg conduits. One of the valves 155 a in the liquid leg conduits145 is positioned in the upstream liquid conduit 145 a (e.g., near theseparator 103) and is configured to selectively open the liquid legconduits 145 for receiving flow from the liquid outlet 109 into theupstream liquid leg conduit 145 a. Further, each of the downstreamliquid leg conduits 145 b has a valve 155 b that is configured toselectively open and close the respective downstream liquid leg conduit145 b. Thus, the valves 155 b in the downstream liquid leg conduits 145b are operable to selectively route fluid flow from the upstream liquidleg conduit 145 a to one or more of the multiphase flow metering systems121, 123. For example, the valves 155 b in the downstream liquid legconduits 145 b can be operated to switch flow through the liquid legconduits 145 back and forth from one of the multiphase flow meteringsystems 121, 123 to the other to reroute the flow of fluid through theliquid leg conduits.

The plurality of valves also includes a set of valves 157 a, 157 b inthe bypass conduits 147 that control flow of fluid through the bypassconduits. One of the valves 157 a in the bypass conduits 147 ispositioned in the upstream liquid conduit 147 a and is configured toselectively open the bypass conduits for receiving flow directly fromthe petroleum wells. Further, each of the downstream bypass conduits 147b has a valve 157 b that is configured to selectively open and close therespective downstream bypass conduits. Thus, the valves 157 b in thedownstream bypass conduits 147 b are operable to selectively route fluidflow from the upstream bypass conduit 147 a to one or more of themultiphase flow metering systems 121, 123. For example, the valves 157 bin the downstream bypass conduits 147 b can be operated to switch flowthrough the bypass conduits back and forth from one of the multiphaseflow metering systems 121, 123 to the other to reroute the flow of fluidthrough the bypass conduits 147. The bypass valves 159 also include avalve 159 c upstream of the separator 103 that is configured toselectively open and close the inlet 105 to the separator 103.

The system also has a control system 161 configured to control operationof the valves 151 in the fluidic system 141. The control system 161 canreside in one or more components. For example, some or all of thecontrol system 161 can be part of or accompany a net oil computerassociated with one or both of the Coriolis meters, such as the net oilcomputer 137 on the skid 131 illustrated in FIG. 7. Likewise, theprocessor 161 can be a separate component that communicates (e.g.,wirelessly or through communication lines) with other components of thesystem. Moreover, the functions ascribed to the control system 161herein can be divided among multiple separate processing components. Thecontrol system 161 is suitably also configured to selectively andsequentially route the output of one or more wells selected from a groupof N wells to the fluidic system 141 to perform a series of well testson the wells, for example using any convention well switching systems(not shown). Moreover, the control system 161 is suitably configured toimplement multiple different measurement modes of the metering system101 by opening and closing selected valves 151 in the fluidic system141. More information about some of the possible measurement modes willbe provided below. In general, however, the control system 161implements different measurement modes by routing fluid from thepetroleum wells through the fluidic system 141 in different ways andchanging how measurements of the production fluids are taken. Thecontrol system 161 is suitably configured to select from one of severaldifferent measurement modes to match current operating conditions (e.g.,flow rate into the system, gas void fraction, etc.) to the performancecapabilities of the multiphase flow metering systems 121, 123. Ingeneral, the control system 161 routes fluid through the fluidic system141 differently for each mode.

For example, the control system 161 is suitably configured to operatethe bypass valves 157 a, 157 b, 157 c to bypass the separator 103 anduse one or more of the multiphase metering systems 121,123 to providedynamic measurement of the production fluids, including near real timeindividual flow rate measurements for oil, water, and gas, whenoperating conditions are consistent with operation of the multiphasemetering systems in this manner. As used herein, the phrase “dynamicmeasurement” refers to a measurement that provides time varyingindividual flow rate measurements for oil, water, and gas that can becorrelated with the flow rates of the constituents into the system 101from the well under test. Similarly, a “dynamic measurement mode” is onethat provides dynamic measurements.

Conversely, the control system 161 is suitably configured to operate thevalves 151 to direct fluids produced from the wells to the separator 103when operating conditions are not conducive to use of the multiphaseflow metering systems 121, 123 to provide dynamic measurements (e.g., ifthe gas void fraction is above a threshold amount). When a measurementmode uses the separator 103, the control system 161 operates the valves151 to route liquids from the separator 103 to one of the multiphaseflow metering systems 121, 123 through the liquid leg conduits 145 andto route gas from the separator to the other of the multiphase flowmetering systems through the gas leg conduits 143. Since dynamicmeasurements are more desirable in most cases than non-dynamicmeasurements, the control system 161 is suitably configured to route allfluid flow received from the well through the bypass conduits 147 whenit determines the current operating conditions allow separate flow ratemeasurements of oil, water, and gas through the system.

The system 101 can include one or more of several different componentsconfigured to provide information for use by the control system 161 todetermine whether or not to bypass the separator 103. For example, oneor more sensors can be installed in a line leading from the wells to thesystem 101 to provide information about the gas void fraction and/ortotal flow rate of fluids currently being directed into the system. Themultiphase metering systems 121, 123 will also provide flow ratemeasurements that can be used by the control system 161 to assess totalflow rate of fluid through the system 101. Moreover, the multiphase flowmetering systems 121, 123 may also be able to provide information aboutthe gas void fraction or other characteristics of the fluid flow whichmay be used by the control system 161 to determine which measurementmode to select and when to implement a change in the current measurementmode.

Several different measurement modes that can be implemented inconnection with the system 101 illustrated in FIG. 6 are listed in Table1 below:

TABLE 1 Various Measurement Modes Liquid Meter 1 Meter 2 Operating FlowGas Void (Capacity of (Capacity of Measurement Mode Rate FractionSeparator 1-5 units) 5-20 units) Quality 1 0-1 0-100% In Use Liquid LegGas Leg Conventional units 2 1-5 0-50%  Bypassed Multiphase Not In UseEnhanced/Dynamic units Flow 3 1-5 50-100%  In Use Liquid Leg Gas LegConventional units 4 5-20 0-50%  Bypassed Not In Use MultiphaseEnhanced/Dynamic units Flow 5 5-20 50-100%  In Use Gas Leg Liquid LegConventional units 6 20-25 0-50%  Bypassed Multiphase MultiphaseEnhanced/Dynamic units Flow FlowIn the example set forth in Table 1, the 1st multiphase flow meteringsystem 121 has a minimum flow rate of 1 unit and a maximum flow rate of5 units. The 2nd multiphase flow metering system 123 has a minimum flowrate of 5 units and a maximum flow rate of 20 units. The liquid flowrate and gas void fraction columns refer to the flow rate and gas voidfraction of fluids entering the system.Mode 1—Very Low Flow Rate

In Mode 1 the control system 161 operates the valves 151 to direct fluidfrom the wells to the separator 103. The control system 161 is suitablyconfigured to pick Mode 1 when the total flow rate of fluid into thesystem is less than the minimum flow rate for the smallest of multiphasemetering systems 121. The separator 103 is used because the fluid flowrate is too low to use any of the multiphase flow metering systems 121,123 to provide dynamic measurements. One of the metering systems 123 isused to measure gas flow from the separator 103 through the gas legconduits 143 and the other 121 is used to measure liquid flow from theseparator through the liquid leg conduits 145. As indicated in Table 1,the smaller multiphase flow metering system 121 is used to measure theliquid because the flow rate of liquid during very low flow rate intothe system will better match the operating range of the smaller systemand it is expected that the control strategy for operating the separatorwill result in periodic batches of gas being released, which can bemeasured by the larger system in spite of the low overall flow ratebecause gas will typically be released only periodically. The systemoutput during the Very Low Flow Rate Measurement Mode providesconventional type measurements on the liquid leg and gas legrespectively. In other words, the measurements are accurate whentotalized or averaged over a sufficiently long time period, but dynamicmeasurements are not available due to the settling time in the separator103 and/or control strategies that may be used to control operation ofthe separator.

Mode 2—Low Flow Rate Dynamic

In Mode 2 the control system 161 operates the valves 151 to bypass theseparator 103 and direct all flow from the wells through the bypassconduits 147 to the smallest of the multiphase flow metering systems121. The control system 161 is configured to pick Mode 2 when the flowrate is within the operating range of the smallest multiphase flowmetering system 121 and the gas void fraction is within thespecifications for operation of the smaller multiphase metering systemin a dynamic multiphase mode (e.g., GVF is less than a threshold value,such as about 50% or less). In the Low Flow Rate Dynamic MeasurementMode, the control system 161 directs all fluids received by the system101 to the smallest multiphase flow metering system 121, which providesenhanced dynamic multiphase measurements.

Mode 3—Low Flow Rate Conventional

In Mode 3 the control system 161 operates the valves 151 to direct allflow received by the system 101 to the separator 103. The control system161 is suitably configured to pick Mode 3 when the flow rate is withinthe specifications for the smallest multiphase flow metering system 121but the gas void fraction is too high to use the metering systems 121,123 to obtain dynamic measurements. One of the metering systems 123 isused to measure gas flow from the separator 103 through the gas legconduits 143 and the other 121 is used to measure liquid flow from theseparator through the liquid leg conduits 145. As indicated in Table 1the smaller system 121 is used to measure the liquid because the flowrate of liquid through the system 101 will better match the operatingrange of the smaller metering system. The system output during the LowFlow Rate Conventional Measurement Mode is conventional typemeasurements on the liquid leg and gas leg respectively.

Mode 4—Medium Flow Rate Dynamic

In Mode 4 the control system 161 operates the valves 151 to bypass theseparator 103 and direct all flow from the wells through the bypassconduits 147 to the larger of the multiphase flow metering systems 123.The control system 161 is configured to pick Mode 4 when the flow rateis within the operating range of the larger multiphase flow meteringsystem 123 and the gas void fraction is within the specifications foroperation of this system in a dynamic multiphase mode (e.g., GVF is lessthan a threshold value, such as about 50% or less). In the Medium FlowRate Dynamic Measurement Mode, the control system 161 directs all fluidsreceived by the system 101 to the larger of multiphase flow meteringsystem 123, which provides enhanced dynamic multiphase measurements.

Mode 5—Medium Flow Rate Conventional

In Mode 5 the control system 161 operates the valves 151 to direct allflow received by the system 101 to the separator 103. The control system161 is suitably configured to pick Mode 5 when the flow rate is withinthe specifications for the larger multiphase flow metering system 123but the gas void fraction is too high to use that metering systems toobtain dynamic measurements. One of the metering systems 121 is used tomeasure gas flow from the separator 103 through the gas leg conduits 143and the other 123 is used to measure liquid flow from the separatorthrough the liquid leg conduits 145. As indicated in Table 1 the largersystem 123 is used to measure the liquid because the flow rate of liquidthrough the system 101 will better match the operating range of thelarger metering system. The system output during the Medium Flow RateConventional Measurement Mode is conventional type measurements on theliquid leg and gas leg respectively.

Mode 6—High Flow Rate Dynamic

In Mode 6 the control system 161 operates the valves 151 159 to bypassthe separator 103 and direct all flow from the wells through the bypassconduits 147 to the multiphase flow metering systems 121, 123, which areused in parallel. The control system 161 is configured to pick Mode 6when the flow rate is above the maximum flow rate capacity of the largermetering system 123 but within the operating range of both meteringsystems 121, 123 working in parallel to collectively measure all thefluid and the gas void fraction is within the specifications foroperation of the metering systems in a dynamic multiphase mode (e.g.,GVF is less than a threshold value, such as about 50% or less). In theHigh Flow Rate Dynamic Measurement Mode, all of the valves 157 a, 157 bin the bypass conduits 147 are open to provide maximum capacity.Meanwhile the valve 159 c controlling the inlet 105 to the separator 103is closed to prevent flow of fluid into the separator.

The various modes set forth above are provided for illustrativepurposes. The cutoff points between modes, the criteria used to pick aparticular mode, and the way fluid is routed through the system can bevaried without departing from the broad scope of the invention. Also,the number of multiphase flow metering systems can be increased from twoto three or more. For example, referring to FIG. 11 the gas leg conduits143, liquid leg conduits 145, and bypass conduits 147 can includeadditional downstream conduits 143 b, 145 b, 147 b connecting therespective upstream conduits 143 a, 145 a, 147 a to additionalmultiphase flow metering systems, such as the third multiphase flowmetering system 125 illustrated in FIG. 11.

The system 101 described herein allows dynamic multiphase measurementsto be provided over a wide range of potential well-flow rates. Existingconventional separation-based well test systems can easily be upgradedto create the system 101 by adding the multiphase flow meters 121, 123and conduits 143, 145, 147 to the existing systems. Moreover, the system101 is also suitable for use in new installations. The system 101 canalso provide improved robustness to gas carry under, liquid carry over,and dissolved gas breakout when the separator 103 is in because themultiphase meters 121, 123 can still provide multiphase measurements,and thereby detect presence of gas in the separated liquid and/orpresence of liquid in the separated gas, even when the system is notoperating in a dynamic mode. Thus, liquid carry over, gas carry under,gas breakout, and other such events can be detected by the system 101.This increased robustness can also make it reasonable to reduce the sizeand cost of the separator 103 because it may no longer be considered asimportant to achieve complete separation under the full range ofoperating conditions that could be encountered.

When introducing elements of aspects of the invention or the embodimentsthereof, the articles “a,” “an,” “the,” and “said” are intended to meanthat there are one or more of the elements. The terms “comprising,”“including,” and “having” are intended to be inclusive and mean thatthere may be additional elements other than the listed elements.

In view of the above, it will be seen that several advantages of theaspects of the invention are achieved and other advantageous resultsattained.

Not all of the depicted components illustrated or described may berequired. In addition, some implementations and embodiments may includeadditional components. Variations in the arrangement and type of thecomponents may be made without departing from the spirit or scope of theclaims as set forth herein. Additional, different or fewer componentsmay be provided and components may be combined. Alternatively or inaddition, a component may be implemented by several components.

The above description illustrates the aspects of the invention by way ofexample and not by way of limitation. This description enables oneskilled in the art to make and use the aspects of the invention, anddescribes several embodiments, adaptations, variations, alternatives anduses of the aspects of the invention, including what is presentlybelieved to be the best mode of carrying out the aspects of theinvention. Additionally, it is to be understood that the aspects of theinvention is not limited in its application to the details ofconstruction and the arrangement of components set forth in thefollowing description or illustrated in the drawings. The aspects of theinvention are capable of other embodiments and of being practiced orcarried out in various ways. Also, it will be understood that thephraseology and terminology used herein is for the purpose ofdescription and should not be regarded as limiting.

Having described aspects of the invention in detail, it will be apparentthat modifications and variations are possible without departing fromthe scope of aspects of the invention as defined in the appended claims.It is contemplated that various changes could be made in the aboveconstructions, products, and process without departing from the scope ofaspects of the invention. In the preceding specification, variouspreferred embodiments have been described with reference to theaccompanying drawings. It will, however, be evident that variousmodifications and changes may be made thereto, and additionalembodiments may be implemented, without departing from the broader scopeof the aspects of the invention as set forth in the claims that follow.The specification and drawings are accordingly to be regarded in anillustrative rather than restrictive sense.

The Abstract is provided to help the reader quickly ascertain the natureof the technical disclosure. It is submitted with the understanding thatit will not be used to interpret or limit the scope or meaning of theclaims.

What is claimed is:
 1. A system for testing production of fluids by oneor more petroleum wells, the system comprising: a separator comprisingan inlet for receiving a multiphase fluid flow from a petroleum well, avessel for containing fluids received through the inlet, a liquidoutlet, and a gas outlet, the gas outlet being positioned at a higherelevation on the vessel than the liquid outlet; first and secondmultiphase flow metering systems, each of the first and secondmultiphase flow metering systems having the capability, over at least aportion of its operating envelope, of separately measuring flow rates ofoil, water, and gas through the respective flow metering system; afluidic system comprising: (i) gas leg conduits fluidicly coupling thegas outlet of the separator to the first and second multiphaseflowmeters; (ii) liquid leg conduits fluidicly coupling the liquidoutlet of the separator to the first and second multiphase flow meteringsystems; (iii) bypass conduits plumbed to direct multiphase fluidthrough the fluidic system to the first and second multiphase flowmetering systems without flowing the fluid through the separator tothereby bypass the separator; and (iv) a plurality of valves configuredto selectively control routing of fluid flow though the fluidic system.2. A system as set forth in claim 1 wherein the gas leg conduits, liquidleg conduits, and bypass conduits each comprises a first conduitconfigured to direct fluid to the first multiphase flow metering systemand a second conduit configured to direct fluid to the second multiphaseflow metering system.
 3. A system as set forth in claim 2 wherein saidplurality of valves includes a valve for each of the first conduits anda valve for each of the second conduits, the valves for the first andsecond conduits being configured to selectively open and close therespective conduit.
 4. A system as set forth in claim 1 wherein thefirst multiphase flow metering system has a relatively higher maximumflow rate capacity and the second multiphase flow metering system has arelatively lower maximum flow rate capacity.
 5. A system as set forth inclaim 1 wherein at least one of the first and second multiphase flowmetering systems comprises a multiphase Coriolis flowmeter.
 6. A systemas set forth in claim 1 wherein each of the first and second multiphaseflow metering systems comprises a multiphase Coriolis flowmeter.
 7. Asystem as set forth in claim 1 wherein each of the first and secondmultiphase flow metering systems comprises a multiphase Coriolisflowmeter in combination with a water cut meter.
 8. A system as setforth in claim 1 further comprising a control system, the control systembeing configured to use the valves to implement multiple differentmeasurement modes, wherein fluid is routed differently through thefluidic system in each of the modes.
 9. A system as set forth in claim 8wherein at least one of the measurement modes is a dynamic measurementmode in which fluid is routed through the bypass conduits to bypass theseparator and at least one of the other measurement modes is a separatedmeasurement mode in which fluid is routed to the separator forseparation into liquids and gas and then liquids are routed from theseparator to one of the first and second multiphase flowmeters and gasis routed from the separator to the other of the first and secondmultiphase flowmeters.
 10. A system as set forth in claim 8 wherein thecontrol system is further configured to: determine whether or not thecurrent operating conditions allow the first and second multiphase flowmetering systems, collectively or individually, to provide separate flowrate measurements of oil, water, and gas through the system; and routeall fluid flow received from the well through the bypass conduits whenthe controller determines the current operating conditions allowseparate flow rate measurements of oil, water, and gas through thesystem.
 11. A system as set forth in claim 10 wherein the firstmultiphase flow metering system has a relatively higher maximum flowrate capacity and the second multiphase flow metering system has arelatively lower maximum flow rate capacity and wherein the controlsystem is further configured to: determine a current flow rate receivedfrom the well; and implement a low flow rate dynamic measurement modewhen: (i) the controller determines the current operating conditionsallow separate flow rate measurements of oil, water, and gas through thesystem; and (ii) the current flow rate is below a threshold amountcorresponding to the maximum flow rate capacity of the second multiphaseflow metering system, wherein implementing the low flow rate dynamicmeasurement mode comprises operating the valves to direct substantiallyall fluid flow through the fluidic system to the second multiphase flowmetering system via the bypass conduits, thereby bypassing theseparator.
 12. A system as set forth in claim 11 wherein the controlsystem is further configured to implement a medium flow rate dynamicmeasurement mode when: (i) the controller determines the currentoperating conditions allow separate flow rate measurements of oil,water, and gas through the system; (ii) the current flow rate is abovesaid threshold amount corresponding to a maximum flow rate capacity ofthe second multiphase flowmeter; and (iii) the current flow rate isbelow a second threshold amount corresponding to the maximum flow ratecapacity of the first multiphase flowmeter, wherein implementing themedium flow rate dynamic measurement mode comprises operating the valvesto direct substantially all fluid flow through the fluidic system to thefirst multiphase flow metering system via the bypass conduits, therebybypassing the separator.
 13. A system as set forth in claim 12 whereinthe control system is further configured to implement a high flow ratedynamic measurement mode when: (i) the controller determines the currentoperating conditions allow separate flow rate measurements of oil,water, and gas through the system; and (ii) the current flow rate isabove said second threshold amount, wherein implementing the high flowrate dynamic measurement mode comprises operating the valves to directsubstantially all fluid flow through the bypass conduits to the firstand second multiphase flow metering systems so the first and secondmultiphase flow metering systems collectively meter all fluid flowthrough the system, thereby bypassing the separator.
 14. A system as setforth in claim 8 wherein the control system is further configured to:determine whether or not the current operating conditions allow thefirst and second multiphase flow metering systems, collectively orindividually, to provide separate flow rate measurements of oil, water,and gas being output by the well; and route all fluid flow received fromthe well to the separator when the current operating conditions do notallow separate flow rate measurements of oil, water, and gas by thefirst and second multiphase flow metering systems.
 15. A system as setforth in claim 14 wherein the control system is configured to determinewhether or not the current operating conditions allow the first andsecond multiphase flow metering system, collectively or individually, toprovide separate flow rate measurements of oil, water, and gas beingoutput by the well by comparing a current measured gas void fraction offluid from the well to one or more threshold values corresponding tomaximum gas void fractions for which the first and second multiphaseflow metering systems are operable to provide separate flow ratemeasurements of oil, water, and gas being output by the well.
 16. Asystem as set forth in claim 14 wherein the control system is configuredto direct fluid from the gas outlet through the gas conduits to one ofthe first and second multiphase flow metering systems and to directfluid from the liquid outlet through the liquid conduit to the other ofthe first and second multiphase flow metering systems so one of thefirst and second flow metering systems is used to meter separated gasand the other of the first and second flow metering systems is used tometer separated liquid when the control system determines the currentoperating conditions do not allow the first and second multiphase flowmetering systems to provide separate flow rate measurements of oil,water, and gas.
 17. A system as set forth in claim 8 wherein the controlsystem is configured to: determine whether or not a set of currentoperating conditions allows the first and second multiphase flowmetering systems, collectively or individually, to provide separate flowrate measurements of oil, water, and gas being output by the well; anduse one or more of the first and second multiphase flow metering systemsto provide separate dynamic flow rate measurements for oil, water, andgas when the controller determines the current operating conditionsallow separate flow rate measurements of oil, water, and gas beingoutput by the well.
 18. A system as set forth in claim 1 furthercomprising a third multiphase flow metering system, wherein the gas legconduits fluidicly couple the gas outlet of the separator to the thirdmultiphase flow metering system, the liquid leg conduits fluidiclycouple the liquid outlet of the separator to the third multiphase flowmetering system, and the bypass conduits are plumbed to directmultiphase fluid from the petroleum well to the first, second, and thirdmultiphase flow metering systems without flowing the fluid through theseparator to thereby bypass the separator.
 19. A system as set forth inclaim 18 further comprising a control system, the control system beingconfigured to use the valves to implement multiple different measurementmodes, wherein fluid is routed differently through the fluidic system ineach of the modes, and wherein at least three of the measurement modesare dynamic measurement modes in which fluid is routed through thebypass conduits to bypass the separator and allow for measurement ofsubstantially instantaneous individual flow rates for oil, water, andgas by different combinations of the first, second, and third multiphaseflow metering systems.
 20. A system as set forth in claim 1 furthercomprising a control system configured to selectively and sequentiallyroute the output one or more wells selected from a group of N wells tothe fluidic system to perform a series of well tests on the wells.